Oil Recovery Agents Research Articles

Experimental investigation of the influence of ZnO–CuO nanocomposites on interfacial tension, contact angle, and oil recovery by spontaneous imbibition in carbonate rocks

Researchers have recently focused on applying various nanoparticles/nanocomposites to improve the recovery factor from oil reservoirs. In this study, a new enhanced oil recovery agent, i.e., a ZnO–CuO (ZCO) nanocomposite, was synthesized, and its physicochemical properties are investigated by the scanning electron microscope, Fourier transform infrared spectrometer, Brunauer–Emmett–Teller, X-ray diffraction, and energy diffraction x-rays. The impact of ZCO and ZnO on interfacial tension, wettability change, and zeta potential tests has also been investigated under reservoir conditions. 0.1 weight percent (wt.%) of ZnO and ZCO in injection fluid, which minimizes contact angle and maximizes stability (i.e., minimum zeta potential), has been determined as the optimum concentration. The contact angle and zeta potential at this optimum concentration of ZnO and ZCO are 50.83°, 35.69° and −31.38, −35.65 mV, respectively. Then, the spontaneous imbibition using ZnO- and ZCO-based nanofluids with the optimum concentration is applied to monitor the recovery factor. The 22.5 day-long imbibition operation utilizing base fluid (without nanomaterials), ZnO, and ZCO retrieved 24.95%, 35.74%, and 52.01% of the oil, respectively. Overall, we concluded that injecting the ZCO-based nanofluids in carbonate porous media efficiently improves rocks and fluid parameters and enhances oil recovery.

Optimizing synthesis and application of an enhanced oil recovery agent: stability assessment of the optimized nanostructured PNIPAM/PS core–shell polymer using a developed DLVO-based model

Optimizing synthesis and application of an enhanced oil recovery agent: stability assessment of the optimized nanostructured PNIPAM/PS core–shell polymer using a developed DLVO-based model

Long carbon chain-modified carbon nanoparticles for oil displacement in harsh-condition reservoirs

Carbon nanoparticles, as an emerging type of enhanced oil recovery agent, promising broad prospects in unconventional oil and gas development. However, limitations such as low interfacial activity due to the strong hydrophilicity of carbon nanoparticles and tendency to aggregate under high-temperature and high-salinity conditions restrict their further application. In this study, activity carbon dots (S-CDs) were prepared via a simple two-step hydrothermal reaction. A range of physicochemical techniques characterized S-CDs, revealing their small particle size (1.4 ± 0.01 nm) and narrow distribution, maintaining strong dispersion stability in mineralized water at 130 °C with a concentration of 16 × 104 mg/L. The AFM scanning results indicated that S-CDs possessed strong interfacial wetting control capability, the adhesion force between oil and rock cores (after S-CDs treatment) decreased by 25 times. Particle Image Velocimetry (PIV) confirmed that S-CD adsorbed at the oil-water interface could formed a solid film, which could rupture into smaller oil droplets for convenient backward migration. The results demonstrated that S-CDs improved the interfacial activity while maintaining the hydrophilicity of CDs. In core displacement experiments, 0.05 wt% S-CDs nanofluid reduced injection pressure by 32.4 % and increased recovery rates by 34.9 %. This work provides new insights for the development of high-temperature, high-salinity displacement agents in harsh-condition reservoirs.

Mutual role of dodecylbenzene sulfonic acid on enhanced oil recovery and asphaltene inhibition in low salinity medium: Experimental and XDLVO study

Understanding the molecular interactions during oil recovery processes can shed light on screening new chemicals for future operations. Of particular interest are chemicals capable of providing the mutual role of asphaltene inhibition and interfacial tension reduction at liquid–liquid and rock-liquid interfaces. This study delves into the interfacial interactions between low-salinity brines, model oils containing dodecylbenzene sulfonic acid, and dolomite rock surfaces. In the experimental part, the asphaltene precipitation inhibition efficacy of dodecylbenzene sulfonic acid was evaluated through filtration and precipitation test, and its oil recovery performance was examined from interfacial tension reduction and wettability alteration viewpoints. The theoretical part was then followed by the implementation of the surface energy concept based on the XDLVO theory, where acid-base and Lifshitz-van der Waals interaction energies, as well as the work of cohesion/adhesion between interacting bodies in asphaltene and oil recovery systems, were considered. The results obtained from this study revealed that dodecylbenzene sulfonic acid, owing to its acidic nature and the long alkyl chain in its structure, could simultaneously perform the role of asphaltene inhibitor and oil recovery agents. In particular, asphaltene particles showed less tendency to aggregate and form macrostructures in the presence of low-salinity brines formulated with magnesium chloride. The total interaction energy between asphaltene particles was almost halved by the addition of dodecylbenzene sulfonic acid. The low interfacial tension of 0.16 mN/m between model oil containing 1 wt% of DBSA and low-salinity brine containing 5000 mg/L magnesium chloride and the wettability alteration of the dolomite sample toward water-wetness were also confirmed by theoretical calculations using the concept of work of adhesion.

Wettability alteration of oil‐wet carbonate rocks by chitosan derivatives for application in enhanced oil recovery II: High‐temperature and high‐pressure conditions—Core flooding tests

AbstractBiopolymers, serving as Enhanced Oil Recovery (EOR) agents, are posing challenges and opportunities within the oil industry, particularly in demanding operational conditions. The assessment of trimethyl chitosan (TMC) and its hydrophobized derivative with myristoyl chloride (TMC‐C14) becomes crucial in these rigorous scenarios, presenting a significant challenge for polymer flooding. The study subjected TMC and TMC‐C14 to comprehensive evaluations as EOR agents, employing contact angle measurements, interfacial tension tests using the Drop Shape Analyzer (DSA), and core flood tests under conditions of 60°C, 1000 psi, and elevated salinity. Relative permeabilities were deduced from the results, while spontaneous imbibition tests provided insights into rock wettability. Amott cell tests underscored that both TMC and TMC‐C14 induced accelerated spontaneous oil production within a span of 30 days. Notably, TMC‐C14 exhibited superior interfacial activity compared to TMC, attributed to its hydrophobic segments. The impact on rock wettability was distinct: TMC shifted it towards water‐wet, while TMC‐C14 induced a neutral‐wet condition. This transformation was corroborated by contact angle measurements, imbibition tests, and relative permeability curves. Capillary forces, computed from DSA data and spontaneous imbibition tests, further validated the wettability‐altering tendencies of the chitosan derivatives on the rock. In core flooding tests and relative permeability curves, TMC demonstrated a notable improvement in the recovery factor (RF) compared to seawater. Specifically, RFTMC achieved 69%, surpassing RFbrine at 49%, affirming that the primary mechanism of action for chitosan derivatives lies in their ability to modify rock wettability. This study shows the potential of TMC and TMC‐C14 as effective EOR agents, shedding light on their interfacial activities, impact on rock wettability, and enhanced recovery factors in challenging operational conditions.

Nano-structure of hydrolyzed polyacrylamide strengthened ultra stable nitrogen foam: Lab experiments and molecular dynamics simulation

Foam flooding is an extremely effective method of enhanced oil recovery used to address uneven utilization in strongly heterogeneous reservoirs. However, conventional foam is not stable and is unevenly distributed in oil reservoirs during conventional foam flooding. Hydrolyzed polyacrylamide-strengthened nitrogen foam (HSNF) was therefore proposed to overcome the defects of conventional foam flooding. In this investigation, a comprehensive method was utilized to understand the mechanisms of HSNF with regard to its stability and distribution in reservoirs. In situ experimental characterization and molecular dynamics simulations were designed to examine the characteristics of HSNF. Foam stability was analyzed as a function of the viscosity of the liquid phase, adsorption, and pressure for HSNF and conventional foam. Parallel core flooding experiments were conducted to compare the oil recovery efficiencies of HSNF and conventional foam. Molecular dynamics simulations were utilized to examine the nanostructure of HSNF in brine. Foam stability tests demonstrated that foam stability was enhanced by increasing the viscosity and pressure of the liquid phase and reducing the adsorption capacity of the surfactant. HSNF increased the foam half-life by a factor of 1.67–27.1. The parallel core flooding experiments showed that HSNF effectively initiated flow in low-permeability cores to increase the mobilization of oil even when the permeability ratio was 14.86. However, conventional foam only achieved similar performance at a permeability ratio of less than 10.64. The molecular dynamics simulations revealed that the addition of hydrolyzed polyacrylamide improved the uniform distribution of the oil displacement agent in porous media, inhibited the diffusion of nitrogen in the foam system, and enhanced the interactions between the water phase and crude oil. This suggests that HSNF is a promising oil recovery agent for use in low-porosity, low-permeability, and strongly heterogeneous sandstone reservoirs.

Monte Carlo dynamics simulation of nanoparticles for enhanced oil recovery

ABSTRACT This research used density functional theory (DFT)-based simulation software to investigate the potential of emerging nanotechnology to alter the physical–chemical interactions of a reservoir system so that a favourable condition for oil displacement could be created. This reservoir was modelled using sandstone (as rock), oil (as any of the hydrocarbon molecules including Decane, Dodecene, Tetradecene and Hexadecene), a particular type of nanoparticles (graphene (GNPs), magnetite (MNPs), zinc oxide (ZNPs), copper oxide (CNPs)) and sodium chloride (NaCl) for nanofluid. From the analysis of adsorption results, we observed that oil adsorption can be reduced to −18.81 from −28.53 Kcal/mol. This was the case for the MNPs in the absence of NaCl. In the presence of NaCl, GNPs showed better performance than others. Arguably, salinity is thus an important factor contributing to the performance of nanofluid as an enhanced oil recovery agent or specifically a wettability modifier. The main mechanisms of the enhanced changes are assumed to be the inhibition of oil adsorption and the profile control capability of GNPs.

Molecular insights into the dispersibility of asphaltene and crude oil rheological properties under the effect of multi-alkylated aromatic amides

In crude oil development, it is important to improve the dispersibility of asphaltene (ASP), and to achieve viscosity reduction. Adding dispersants is a promising solution to postpone the ASP deposition, nevertheless, the effect of dispersants to the oil viscosity is at odds. To provide insight into the role and mechanisms of ASP dispersants in regulating the dispersibility of ASP and the oil rheological properties, we performed computational simulation studies. It is demonstrated that MAA dispersants adsorb onto ASP clusters via the polar interaction, isolating ASP clusters and preventing further aggregation. In addition, dispersed ASP molecules present stronger intermolecular friction with light-weighted components and the hydrogen bond spatial network can be enhanced, thereby leading to the increase of oil viscosity. These molecular insights help to understand the association of crude oil rheological properties with ASP dispersibility, which is expected to facilitate the future development of chemical agents for crude oil recovery.

Optimization of injection parameters of a microemulsion-type oil displacement agent for heavy oil recovery

The conventional viscosity reduction technology through commercial oil-soluble agents for enhanced oil recovery in heavy oil reservoirs has potential safety hazards. In this work, micro-emulsification of heavy oil is proposed as a means of reducing its viscosity for ease of its recovery. The microemulsion-type oil displacement agent was developed, and its performance was characterized by its pseudoternary phase diagram and dynamic light scattering tests. The core tests were used to study the effects of injection volume, injection speed, and subsequent water flooding speed on the oil recovery factors. These results were used to determine the optimal injection parameters. Furthermore, the displacement mechanism for heavy oil was determined based on combined macroscopic and microscopic visual tests. The results showed that the optimal injection volume is 0.15 PV (pore volume), the injection rate is 0.10 ml/min, and the subsequent water flooding rate is 0.20 ml/min. Based on the optimal parameters, the oil recovery efficiency can reach up to 39.83%, which is 25.69% higher than water flooding process. The displacement mechanism of the microemulsion can be divided into three stages. First, when the microemulsion is in contact with the heavy oil, the solubilization occurs spontaneously, and the heavy oil is peeled off from the rock surface. Then, the solvent in the microemulsion interacts with the heavy oil to achieve the viscosity decrease in the heavy oil. Third, during the water flooding process, the viscosity-reduced heavy oil can be emulsified to form oil-in-water emulsion, further realizing the viscosity reduction of heavy oil.

Experimental investigation on supercritical multi-thermal fluid flooding using a novel 2-dimensional model

Supercritical multi-thermal fluid (SCMTF) is a promising alternative to traditional thermal agents for deep heavy oil recovery. However, no 2-dimensional experimental investigation on SCMTF flooding has been conducted due to the limitations of existing apparatuses. Therefore, the primary objective of this study is to develop a novel assembly for investigating the performance of SCMTF flooding. Subsequently, the SCMTF chamber evolution is characterized using newly developed equipment, and enhanced oil recovery (EOR) mechanisms are proposed. Finally, the effects of the injection temperature, injection pressure, scN2/scCO2 mixture, and heavy oil viscosity on SCMTF are comprehensively studied. The results show that the SCMTF chamber displays an inverted trapezoidal shape with a uniform front. SCMTF flooding can enhance heavy oil recovery by 13.36% relative to steam flooding by sweep area expansion, oil mobility improvement, and miscible flooding. Increasing the injection temperature, injection pressure or scN2/scCO2 mixture to SCW molar ratio can facilitate the production of heavy oil, while using SCMTF in an extra-heavy oil cannot maximize the EOR effect of SCMTF. Notably, the high yield of coke produced at elevated temperatures may lead to potential formation damage.

Comparative performance evaluation of modified red onion skin extract as surface active agents for tertiary oil recovery

ABSTRACT Biomass-based recovery agents are fast becoming an innovative, novel solution to the increasing need for eco-friendly, cost-effective chemical agents as the need to cut production cost becomes imperative. Recent studies showed that certain natural materials if modified can suitably replace synthetic chemicals. Red Onion Skin Extract (ROSE) was chemically modified using furfuraldehyde (ROF) and urea (ROFU) and evaluated to determine its oil displacement efficiency at reservoir conditions by evaluating the fluid compatibilities. Two synthetic brine was formulated to replicate the formation of brine with divalent ions present. Compatibility test of the aqueous solution produced highly soluble, compatible fluids at varying temperatures. Type I microemulsion was observed in both surfactants. Sandstone core analysis was performed to ascertain how effective the individual modified derivatives are in recovering bypassed oil at reservoir temperature (90 °C) and pressure (9000 psi). An additional recovery of 22.7% OIIP and 11% OIIP was attained during ROF and ROFU flooding, respectively. The ROSE derivatives show good performance in displacing heavy oil even at reservoir conditions.

Interfacial and rheological investigation of enhanced oil recovery agents derived from Spirulina biomass

This study investigates interfacial and rheological properties of novel, Spirulina-based fluids developed for potential use in enhanced oil recovery (EOR) applications. The purpose of this investigation is to determine the driving mechanism(s) behind the EOR performance of these materials after a previous study concluded that the EOR fluids are a promising technology with up to 96% recovery of the original oil in place (OOIP). It was then hypothesized that the EOR mechanism arose from the interfacial energy effects and/or the rheological properties. In this study, Arthrospira platensis (Spirulina) biomass is modified by different denaturants (sodium hydroxide, citric acid, and urea) and tested for a wide range of interfacial and rheological properties. The interfacial properties include surface tension, interfacial tension with hydraulic oil, contact angle against silicon dioxide, and work of adhesion between the fluid and the silicon dioxide surface. The rheology focuses on determining fluid viscoelastic properties and flow behaviors. Additionally, this study compares and correlates the results amongst each other, which also includes pH, EOR performance, and denaturant concentration.The EOR performance of these fluids strongly correlates with the increased viscosity, reduced interfacial tension (IFT), and increased wettability in the EOR fluids. All of the investigated EOR solutions reduced the IFT. Most of the EOR solutions were found to be mostly shear-thinning with shear-thickening approximately in the 2,000–5,000 s−1 range. From the results, it is concluded that the performance of the different types of EOR fluids is based on different mechanisms. Sodium hydroxide-based fluids are driven by increased low-shear viscosity, reduced IFT, alkaline pH shift, and improved wettability. The citric acid-based fluids do not exhibit high viscosity values in the low shear range, which indicates that their EOR performance seems to be driven by reduced IFT, acidic pH shift, improved wettability, and increased fluid rigidity by the generation of crosslinks in the macromolecular structure. Urea-based fluids did not exhibit improved viscosity, which means that their modest EOR performance is likely driven by reduced IFT and improved wettability. While a shear-thickening rheology is often considered to be a mechanism for improving EOR, it is concluded that the shear-thickening effect is not a dominant mechanism for these fluids, especially since the highest performing EOR fluid (highest NaOH concentration) did not display shear thickening.

Nanofluid formulation based on the combined effect of silica nanoparticles and low salinity water for Enhanced Oil Recovery in sandstones

Recent studies have indicated that nanofluids that combine silica nanoparticles and low salinity water have a promising character as Enhanced Oil Recovery agents for application in sandstones. In view of that, this work aimed to investigate the stabilization mechanism of silica nanoparticles in aqueous medium and the effects that low-salinity silica nanofluids induce on fluid/fluid and rock/fluid interactions in order to generate contributions to the understanding of the oil recovery mechanisms of this potential injection fluid. Therefore, experiments were carried out with nanofluids containing silica nanoparticles at concentrations between 0.01 and 0.2 wt% dispersed both in deionized water (DW) and in a low salinity water (LSW) containing a Total Dissolved Solids of 1343.4 mg/L. The results showed that the dynamic viscosity of the nanofluids exceeds that of DW by, at most, only about 4.23%. The size of the silica nanoparticles in the nanofluids did not increase over 200 nm and was not consistently affected by factors such as nanoparticle concentration, dispersing fluid or time elapsed after sonication of the nanofluids. In general, the interfacial tension between the crude oil and DW was not substantially changed when the aqueous phase was replaced by the nanofluids. On the other hand, the zeta potential of silica nanoparticles was significantly decreased when they were dispersed in LSW in comparison to DW. The contact angle analyzes evidenced the ability of the nanofluids in altering the wettability of crude-oil aged sandstone surfaces towards more water-wet conditions, notably the nanofluids with higher concentrations of silica nanoparticles and prepared with LSW.

Molecular dynamics simulation of heavy oil dissolution in supercritical water and multi-component thermal fluid

For upgrading, SHS was suitable for carbon residue reduction and SCW and MCTF were suitable for viscosity reduction. For thermal recovery, SCW was able to show spontaneous miscibility in shallower reservoirs compared to MCTF and SHS may form coke and plug pores.

Synthesis and pore-scale visualization studies of enhanced oil recovery mechanisms of rice straw silica nanoparticles

There is increasing interest in synthesis of silicon dioxide (SiO2) nanoparticles from agricultural biomass waste because the process is cost-efficient and eco-friendly. However, the application of rice straw SiO2 nanoparticles as enhanced oil recovery (EOR) agents have not been examined in detail. Moreover, the pore-scale mechanisms governing the mobilization and displacement of resident oil during rice straw silica nanofluids (RS SNF) flooding is rarely reported in literature. In this study, SiO2 nanoparticles (nanosilica) were synthesized from rice straw and characterized. Oil-water interfacial tension (IFT) and contact angles were measured to assess the performance of RS SNF as EOR agents. Pore-scale visualization experiments were conducted using 2-dimensional micromodel to identify the prevailing EOR mechanisms of RS SNF flooding. Significant reduction in oil-water IFT and contact angles were obtained in presence of RS SNF. These results were comparable to the performance of commercial silica nanofluids, suggesting that RS SNF could be utilized as favourable substitute to commercial SNF. The ideal rice straw nanosilica concentration for achieving optimum residual oil mobilization and microscopic sweep was identified as 0.1 wt% from pore-scale visualization experiments. At similar conditions, the oil retained (oil saturation) within the micromodel was determined by Image J software as 28.51% after 0.05 wt% RS SNF flooding and 23.73% after 0.1 wt% RS SNF flooding. The oil trapped in the micromodel after rice straw nanosilica–SDS and commercial nanosilica–SDS solutions injections were comparable at 19.35% and 18.33% respectively. The displacement efficiency and microscopic sweep was much higher when the synergy of nanoparticles and 0.2 wt% sodium dodecyl sulfate (SDS) solutions were injected into the micromodel due to the lowest oil-water IFT and contact angles achieved by SiO2/SDS solutions. The SiO2/SDS fluid front propagated uniformly and in piston-like movement pattern, suggesting that the impact of viscous force over capillary oil retention forces was significantly higher. During nanofluids flooding, uniform invasion of the displacing fluid was observed at the onset of fluid injection, the nanofluid become thicker whereas the oil become thinner with the advancement of the displacing front. However, fingering of the displacing fluid front was noticed with time, resulting in progression of displacement fronts with dendritic and dispersive patterns.

Investigating the potential of microbial enhanced oil recovery in carbonate reservoirs using Bacillus persicus

In this study, several laboratory experiments were conducted to evaluate the performance of Bacillus persicus as a microbial enhanced oil recovery (MEOR) agent in conventional and fractured carbonate reservoirs. In these experiments, it was observed that using the microbial solution as an imbibing fluid can produce 12.5% of the original oil in place. Complementary imbibition experiments demonstrated that lower recoveries are achievable using Sodium Dodecyl Sulfate (SDS) surfactant and supernatant solutions. In order to investigate effective mechanisms, various experiments, including wettability alteration measurements, biosurfactant production tests, viscosity, and pH measurements, were performed. The contact angle tests exhibited that the selected microorganism can alter the wettability of carbonate surfaces by reducing the water/oil contact angle from 132° to 54°, representing a change from an oil-wet to water-wet state. Bacillus persicus also showed favorable results in biosurfactant production tests, including interfacial tension, emulsion index E24%, and oil displacement experiments. The viscosity measurements showed that the bacterial solution could decrease oil viscosity by about 27%. Moreover, no significant changes were found in the pH of the microbial solution during incubation and after treatment. Finally, core flooding experiments exhibited that microbial solution injection as a tertiary oil recovery method could recover 37.52% of the original oil in place. The results obtained in this study demonstrated the potential of MEOR plans targeting oil-wet/mixed-wet fractured and non-fractured carbonate reservoirs.

Laboratory evaluation of red onion skin extract and its derivative as biomass-based enhanced oil recovery agents

The use of natural alternatives as oilfield chemicals is gradually gaining attention among researchers due to their eco-friendly nature. The aim of this study was to determine the efficiency of red onion skin extract (ROSE) at recovering residual oil using the mechanism of surfactant flooding in sandstone reservoirs at reservoir conditions and compare its effectiveness in its pristine and modified state. ROSE was obtained by solvent extraction of the waste biomass (red onion skin) using acetone. The extract was chemically modified using glutaraldehyde. Phase behavior analysis in the presence of divalent ions at high temperatures (80 ˚C) and sandstone core flooding were performed to determine the fluid compatibility and displacement efficiency. Results show high compatibility and solubility of pristine (unmodified) and modified ROSE in soft and hard brine. Core flooding analysis showed a higher recovery of 32.1% and 36.5% original oil in place (OOIP) for 0.3 wt.% modified ROSE as compared to a recovery factor of 31.8% and 35.0 % OOIP for 0.5% unmodified ROSE in soft and hard brine respectively. It further reveals an increase in additional recovery at surfactant concentration in hard brine above critical micelle concentration (CMC). Results of statistical significance test showed that modified ROSE exhibited superior performance and a higher recovery relative to unmodified ROSE especially in hard brine. This is a novel work as red onion skin extract was derivatized with glutaraldehyde and successfully recovered additional residual oil under hard brine and reservoir temperature making them potential surface-active agents for chemical enhanced oil recovery.

Comprehensive experimental investigation of the effective parameters on stability of silica nanoparticles during low salinity water flooding with minimum scale deposition into sandstone reservoirs

Recent studies showed the high potential of nanofluids as an enhanced oil recovery (EOR) agent in oil reservoirs. This study aimed to investigate the effects of salts and ions, the salinity of aqueous solution, total dissolved solids (TDS), scale deposition of mixing brines, surface charge as zeta potential (ZP) value, and pH of injected brines as low salinity water (LSW) on the stability of silica nanoparticles (NPs). The experiments were conducted on the stability of silica NPs at different concentrations and brines to determine optimum salinity, dilution, cations, and anions concentrations. The results showed that 10 times diluted seawater (SW#10D) was optimum low salinity water (OLSW) as injected LSW and water-based nanofluids. Results showed that by decreasing the salinity, increasing seawater dilution, and removing Mg2+ and Ca2+ cations, the amount of scale deposition decreased, and the brine's brine's brine stability of NPs in brine improved. At the optimum salinity and dilution conditions, compared with other salinities, there was less scale formation with more nanofluid stability. Obtained results from ZP measurements and dynamic light scattering (DLS) showed that by removing divalent ions (Mg2+ and Ca2+) of water-based nanofluid (low salinity hard water (LSHW) composition), more NPs were attached to the surface due to the reduction in repulsive forces between the NPs. Therefore, at optimum low salinity soft water (OLSSW), more wettability alteration occurred compared with optimum low salinity hard water (OLSHW) due to the more stability of NPs in OLSSW. The obtained results from the contact angle measurements, surface adsorption of the NPs by FESEM images, and ZP measurements showed that the predominant mechanism in enhancing oil recovery by nanofluid was the wettability alteration by disjoining pressure. According to wettability alteration results, the silica NPs with an optimized concentration in the optimized LSHW and LSSW compositions could be improved the wettability alteration by up to 23.37% and 55.81% compared with the without NPs. The optimized LSSW compared with LSHW composition could be improved the wettability alteration by up to 11.69%. In addition, OLSSW-based nanofluid compared with OLSHW could be increased wettability alteration toward strongly water-wet by up to 33.44%.

A comprehensive study on the application of a natural plant-based surfactant as a chemical enhanced oil recovery (CEOR) agent in the presence of different ions in carbonate reservoirs

Surfactant flooding is a promising CEOR approach in carbonate reservoirs and its efficiency has been verified. Commercial surfactants may impose various health and environmental issues. Therefore, utilizing a natural biodegradable surfactant at a low cost is a valuable option for the petroleum industry. In this research, a non-ionic surfactant derived from Acanthophyllum Plant Root Extract (APRE) was used as a bio-surfactant. The EOR potential of this surfactant was evaluated through various tests. Oil-water system interfacial tension (IFT) measurement, contact angle test for carbonate rock wettability alteration assessment, emulsion stability, compatibility, and surfactant flooding test were conducted. The effect of different ions of various salts on the IFT, carbonate rock wettability and the chemical interactions were also studied. The emulsion stability created by the surfactant was assessed through observational tests. The compatibility test (at 25 °C) showed that negligible sediment below the salinity of 50,000 ppm was formed. The IFT at CMC in formation water (optimum concentration of 12000 ppm) was reduced to 1.06 mN/m from an initial value of 2.16 mN/m. The optimum IFT value at different salinities was also determined. The wettability of the carbonate rock from a strongly oil-wet state (168°) was altered to water-wet (60.3°) in the presence of surfactant and FW with a concertation of 10,000 ppm. In the core flood test, the effect of different slug sizes and soaking time was also determined. It was observed that increasing slug size results in a lower mobility ratio and consequently higher oil recovery.

Nano-surface Functionality of Zinc Ferrite: Ascorbic Acid Nanofluid Application in Enhanced Oil Recovery

Background: The compromising effect of reservoir’s compositions on the acceleration of oil towards the production center during recovery efforts in both primary and secondary applications prelude the application of nanofluid in the oil industry. Objective:: This study explores the efficacy of Ascorbic acid on the surface of Zinc Ferrite nanoparticles in interfacial tension (IFT) and wettability modification. Method: The use of co-precipitation method for the synthesis of Zinc Ferrite nanoparticles (ZNP) was successful at varying temperatures. Consequently, ascorbic acid NPs were coated on ZNP and their brine based nanofluid was prepared. Results: The effects of calcination temperature on the morphology, structure and the crystallinity size were investigated. In concentration influence determination, wettability alteration (W.A) was the most affected mobility factor at 0.15M. However, at 0.25M higher concentration, the IFT, W.A and nanofluid’s stability were relatively improved significantly. Conclusions: This research enhances our understanding of the ascorbic acid effect on ZNP and the fascinating impact of their combined usage as an enhanced oil recovery agents. Ascorbic acid improved the efficiency of the coated ZnFe2O4 nanoparticles on IFT and contact angle.